This disclosure relates generally to pressurized gas systems, such as gasification systems used in an integrated gasification combined-cycle (IGCC) power generation plant, from which it is desired to recover carbon dioxide with a minimal decrease in pressure in the carbon dioxide. More particularly, the disclosure relates to improved methods of removing carbon dioxide (CO2) from synthesis gas streams produced using an IGCC power generation plant.
Most known IGCC plants include a gasification system that is integrated with at least one power-producing turbine system. For example, at least some known gasification systems convert a mixture of fuel; air or oxygen; steam, water and/or CO2 into a synthesis gas, or “syngas.” The syngas is channeled to the combustor of a gas turbine engine, which powers an electrical generator that supplies electrical power to a power grid. Exhaust from at least some known gas turbine engines is supplied to a heat recovery steam generator (HRSG) that generates steam for driving a steam turbine. Power generated by the steam turbine also drives an electrical generator that provides electrical power to the power grid.
In recent years, there has been a growing concern related to greenhouse gas emissions, particularly, CO2. At least some known gasification systems associated with IGCC plants typically produce a “raw” syngas fuel which includes carbon monoxide (CO), hydrogen (H2), carbon dioxide (CO2), carbonyl sulfide (COS), and hydrogen sulfide (H2S). The CO2, H2S, and COS are typically referred to as acid gases. IGCC technology per se involves the potential of high efficiency, thus reducing the CO2 output accordingly. Moreover, H2S and COS, generated with the use of IGCC plants, are generally removed from the raw syngas fuel to produce a “clean” syngas fuel for combustion within the gas turbine engines. Such acid gas removal is performed with an acid gas removal subsystem that typically includes at least one clean-up system to remove a majority of H2S and/or COS.
Conventionally, provisions are only made for removing COS and H2S in an IGCC plant. More particularly, the H2S is removed by solvent processes such as amine solvent removal or physical solvent removal, which produces H2S at low pressure. The sulfur can then further be recovered. Similar procedures can be used for COS, however, these processes are typically not as efficient and as such may require a hydration step that converts COS to H2S prior to using a solvent.
With the requirements for mitigation of CO2 being introduced into the atmosphere, conventional removal processes are not adequate. Accordingly, there is a need to modify or replace the conventional acid gas removal (AGR) systems to recover CO2 for sequestration or deposition as a product. One method that has been suggested for CO2 recovery, is to modify the solvent based technologies currently used to facilitate the recovery of both CO2 and H2S in sequential units, or by developing an integrated CO2/H2S AGR system. One disadvantage of such a system of this type is that the acid gases including CO2 are recovered at low pressure. Carbon dioxide, however, must be supplied at elevated pressures for recycling to the gasifier, sequestration, deposition, pipelining and the like. As such, CO2 removed from an integrated system would require compression prior to ultimate use in the IGCC plant that will be costly and inefficient.
As such, there is a need in the art for the development of a less expensive and more effective removal method for removing and recovering CO2 from gas streams, such as synthesis gas streams, at elevated pressures. More specifically, there is a need for an alternative means of removing CO2 from syngas without the need for compression of the CO2 before sequestration or other deposition. Additionally, it would be advantageous if the energy requirements of removal could be reduced by the removal method.